Oilfield activities involve various sub-activities used to locate and gather hydrocarbons. Various tools, such as seismic tools, are often used to locate the hydrocarbons. One or more wellsites may be positioned along an oilfield to locate and gather the hydrocarbons from subterranean reservoirs of an oilfield. The wellsites are provided with tools capable of advancing into the ground and removing hydrocarbons from the subterranean reservoirs. Production facilities are positioned at surface locations to collect the hydrocarbons from the wellsite(s). A target fluid is drawn from the subterranean reservoir(s) and passes to the production facilities via transport mechanisms, such as tubing. Various equipment is positioned about the oilfield to monitor and manipulate the flow of hydrocarbons from the reservoir(s).
During oilfield activities, it is often desirable to monitor various oilfield parameters, such as fluid flow rates, composition, etc. Sensors may be positioned about the oilfield to collect data relating to the wellsite and the processing facility, among others. For example, sensors in the wellbore (or borehole) may monitor fluid composition, sensors located along the flow path may monitor flow rates, and sensors at the processing facility may monitor fluids collected. The monitored data is often used to make real-time decisions at the oilfield. Data collected by these sensors may be further analyzed and processed.
The processed data may be used to determine conditions at the wellsite(s) and/or other portions of the oilfield, and make decisions concerning these activities. Operating parameters, such as wellsite setup, drilling trajectories, flow rates, wellbore pressures, production rates and other parameters, may be adjusted based on the received information. In some cases, known patterns of behavior of various oilfield configurations, geological factors, operating conditions or other parameters may be collected over time to predict future oilfield activities.
Oilfield data is often used to monitor and/or perform various oilfield activities. There are numerous factors that may be considered in operating an oilfield. Thus, the analysis of large quantities of a wide variety of data is often complex. Over the years, oilfield applications have been developed to assist in processing data. For example, simulators, or other scientific applications, have been developed to take large amounts of oilfield data and to model various oilfield activities. Typically, there are different types of simulators for different purposes. Examples of these simulators are described in Patent/Application Nos. U.S. Pat. No. 5,992,519, WO2004049216 and U.S. Pat. No. 6,980,940.
Numerous oilfield activities, such as drilling, evaluating, completing, monitoring, producing, simulating, reporting, etc., may be performed. Typically, each oilfield activity is performed and controlled separately, sometimes with the use of computer systems using separate oilfield applications that are each written for a single purpose. Thus, many such activities are often performed using separate oilfield applications. In some cases, it may be necessary to develop special applications, or modify existing applications to provide the necessary functionality, such as modeling borehole stability.
In one example, an established model for borehole stability is found in the paper “A Borehole Stability Model To Couple the Mechanics and Chemistry of Drilling Fluid/Shale Interaction” by Mody et al., published as SPE25728 at 1993 IADC/SPE Drilling Conf., Amsterdam, Feb. 23-25, 1993. In another example, a Pore Pressure Transmission (PPT) experiment is described in the paper “Interpretation and Application of Acoustic and Transient Pressure Response to Enhance Shale (In)Stablility Predictions” by Tare et al., published as SPE63052 at 2000 SPE Annual Technical Conference and Exhibition, Dallas, Oct. 1-4, 2000, which is also incorporated herein by reference. The PPT experiment is designed to study time-dependent alterations in shale properties as a function of exposure to drilling fluid. In this paper, a pore pressure change up to 1640 psi (pounds per square inch) was reported based on simulated drilling fluid interaction with shale samples.
FIG. 1 shows a schematic of an experiment for modeling wellbore stability. More details regarding the experiment can be found in SPE63052 referenced above. The experiment establishes a simulation of a type of rock that may be found at or near a formation bearing hydrocarbons or other fluids. In particular, the experiment simulates the pressure and temperature of the formation and fluids under varying circumstances. A rock sample 6, for example from a Pierre shale formation, is placed in a vessel 18 filled with a hydraulic fluid 13. The rock sample 6 is held separate from, but within, the hydraulic fluid 13 by an impermeable jacket 10 (shown as a cross section surrounding the rock sample) and end caps (e.g., lower end cap 14, upper end cap 16). A test fluid is applied at varying pressures to the rock sample 6 circulating through an ingress pipe 2 and egress pipe 4. As a pore pressure of the rock sample 6 responds to the circulating test fluid, a pore pressure gauge 8 reports a changing pressure. In a subterranean formation simulated by the experiment, the pore pressure is the pressure of pore fluid. Pore fluid is a fluid that occupies the gaps between mineral particles of a formation.
Pierre shale, which is used as the rock sample 6 in the experiment shown in FIG. 1, is a substance found in a formation and may be simulated as described above. While Pierre shale is used in the experiment shown in FIG. 1, the experiment is equally applicable to other subterranean formations in various combinations (e.g., sand, clayey sandstone, clay-shale composed of mixed-layer smectite, kaolinite, illite, montmorillonite, chlorite, vermiculate, quartz etc.). In addition, shale may also include varying mixtures of clay, feldspars, pyrite, dolomite, calcite, and apatite, among other minerals.
FIG. 2 shows a graphical representation of pore pressure in an experiment for modeling wellbore stability. More details regarding this experiment can be found in SPE63052 referenced above. Referring to the graph 19, along a vertical axis 21, pressure is recorded in pounds per square inch (psi). Time is measured along a horizontal axis 23. Using the experiment as shown in FIG. 1, the experimenter applies a confining pressure to the rock sample 6, in this example Pierre shale, through hydraulic pressure established inside the vessel 18. At an initial time (time equal to 0 on the horizontal axis) the confining pressure is 1000 psi, and is traced by confining pressure line 20 (in FIG. 2). Initially a simulated pore fluid of an eight percent concentration of salt (solute) in water (solvent) is applied through the ingress pipe 2 (in FIG. 1), traced by pore pressure line 22 (in FIG. 2), to saturate the rock sample 6 (in FIG. 1). As used in this experiment, concentration is a measure of the proportion to which a solvent contains or dissolves a solute. Concentration may be calculated by dividing the amount of solute into the amount of solvent.
Continuing with FIG. 2, once the saturation is achieved during a first time interval 24, the experimenter increases the confining pressure until the confining pressure reaches 4000 psi. In response, the pore pressure climbs, peaks, and settles to an approximate equilibrium pressure at approximately time 5000 minutes after the initial time. Upon the stabilization of the pore pressure after a second time interval 26, the pore fluid is replaced with a drilling fluid that is circulated at a constant pressure. The time-dependent transient behavior of the pore pressure is then recorded in a third time interval 28. The drilling fluid used in the experiment shown in the graph of FIG. 2 is a sodium silicate system containing a 20 percent concentration salt solution. Pore pressure, shown on pore pressure line 22 declines from a high of 3140 psi to approximately 1640 psi. It was pointed out in SPE63052 that reduced pore pressure contributes towards enhancing wellbore stability on a time-dependent basis.
Additional studies on wellbore instability can be found in the paper “Shale-Fluid Interactions Measured Under Simulated Downhole Conditions” by Ewy et al., published as SPE/ISRM 78160 at 2002 SPE/ISRM Rock Mechanics Conference, Irving Tex., Oct. 20-23, 2002. Ewy reports that a pore pressure change up to 1000 psi is caused by shale exposure to a salt solution. This paper, along with the papers SPE25728 and SPE63052 referenced above, relates only to the drilling fluid interaction with shale in the wellbore during a drilling operation.
Studies conducted to enhance wellbore stability during cementing operation in a wellbore have also been described in the paper “Understanding Formation (In)Stability During Cementing” by Heathman et al., published as SPE/IADC 79913 at 2003 SPE/IADC Drilling Conference, Amsterdam, Feb. 19-21, 2003. This paper concerns with cementing fluid/shale interaction in the wellbore during a cementing operation.
More recently, wellbore stability is described in the paper “Stressed Shale Drilling Strategy—Water Activity Design Improves Drilling Performance” by Rojas et al. published as SPE 102498 at 2006 SPE Annual Technical Conference, San Antonio Tex., Sep. 24-27, 2006. Rojas reports that a pore pressure change up to 1000 psi is caused by shale exposure to salt solution. In the paper, the authors note that “Non-aqueous drilling fluids are often chosen to drill troublesome shale formations.” Rojas describes maintaining the integrity and stability of the wellbore in shale formations and refers to a common practice of increasing the drilling fluid salt content to enhance the borehole stability. Rojas further describes that the osmotic effect is a valuable tool for helping maintaining stability in the wellbore.
The papers referenced above describe that wellbore stability in shale formations is estimated to cost the petroleum industry, according to conservative estimates, $700 million to over $1 billion annually. Understanding and modeling mechanisms of shale stability is an ongoing industry effort. Since at least as early as the SPE 4232 paper in 1973 (SPE 4232, September 1973, Stabilizing sensitive shales within inhibited potassium based drilling fluids) until the recent SPE 102498 paper in 2006, the major concerns of the drilling engineer are to keep the wellbore wall from collapsing inward, swelling and, at the same time, to avoid fracturing the wellbore wall and losing circulation.
Another example of an oilfield activity is hydraulic fracturing. Fracturing refers to methods used to stimulate the production of target fluids (i.e., hydrocarbons) resident in the subsurface, for example, oil, natural gas, and brines.
A fracture is a crack or surface of breakage within rock or a formation. Often, fracturing creates a fracture zone through which target fluids and hydrocarbons can more easily flow to the wellbore. A fracture zone is a zone having multiple fractures, or cracks in the formation. A typical fracture zone is shown in context, in FIG. 3.
FIG. 3 shows a diagram of hydraulic fracturing used in oilfield operation. The wellbore 30 extends to and potentially through the fracture zone 32. The vertical extent of the hydrocarbon-producing zone can be coextensive with the fracture-zone height. These two coextensive zones are shown bounded by upper bound 34 and lower bound 45. Fractures are created in a target formation by applying hydraulic pressure through perforations 36, 38, 40, 42, 44, 46 in the well casing. The perforations 36, 38, 40, 42, 44, 46 allow the fracturing fluid to flow from wellbore 30 to the target formation. The reservoir may be present beyond a single fracture zone 32 in the subterranean formation.
Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation. More particularly, when a fluid is injected through a wellbore, the fluid may exit through holes or perforations in the well casing and against the face of the formation. The fluid flows at a pressure and flow rate sufficient to overcome the minimum in situ stress (also known as minimum principal regional stress) to initiate and/or extend a fracture(s) into the formation. In practice, fracturing a well can be a highly complex operation performed with orchestration of equipment, engineers and technicians, and computers that monitor rates, pressures, volumes, in real time.
During a typical fracturing job, tens of thousands of gallons of materials can be pumped into the formation at pressures high enough to actually split the formation, thousands of feet below the earth's surface. Fracturing fluids of the prior art may be based on oil, water, a combination of water and methanol or water and oil. Highly viscous fracturing fluids have been the preferred choice. As a result, pumps with great power are used to inject the fracturing fluids, as well as remove them. The fracturing fluids, other than the salt content they may contain, are considered inert in the sense that they typically have low ionic concentrations when introduced to the wellbore. Fracturing fluids may also be used to transport proppants. A proppant is a solid granular material that may lodge in a fracture and support the sides of the fracture, keeping it open. A proppant may not be effective if the formation adjacent the fractures contains shale or clayey sandstone which may soften because of water adsorption.